System for Generating Steam and for Providing Cooled Combustion Gas to a Secondary Gas Turbine

ABSTRACT

A power plant includes a first gas turbine and a second gas turbine. The first gas turbine includes a turbine extraction port that is in fluid communication with a hot gas path of the turbine and an exhaust duct that receives exhaust gas from the turbine outlet. The power plant further includes a first gas cooler having a primary inlet fluidly coupled to the turbine extraction port, a secondary inlet fluidly coupled to a coolant supply system and an outlet in fluid communication with the exhaust duct. The first gas cooler provides a cooled combustion gas to the exhaust duct which mixes with the exhaust gas to provide an exhaust gas mixture to a first heat exchanger downstream from the exhaust duct. At least one of a compressor and a turbine of the second gas turbine are in fluid communication with the outlet of the first gas cooler.

FIELD OF THE INVENTION

The present invention generally relates to a gas turbine power plantsuch as a combined cycle or cogeneration power plant. More particularly,the present invention relates to a system for generating steam and forproviding cooled combustion gases to a secondary gas turbine.

BACKGROUND OF THE INVENTION

A gas turbine power plant such as a combined cycle or cogeneration powerplant generally includes a gas turbine having a compressor, a combustor,a turbine, a heat recovery steam generator (HRSG) that is disposeddownstream from the turbine and a steam turbine in fluid communicationwith the HRSG. During operation, air enters the compressor via an inletsystem and is progressively compressed as it is routed towards acompressor discharge or diffuser casing that at least partiallysurrounds the combustor. At least a portion of the compressed air ismixed with a fuel and burned within a combustion chamber defined withinthe combustor, thereby generating high temperature and high pressurecombustion gas.

The combustion gas is routed along a hot gas path from the combustorthrough the turbine where they progressively expand as they flow acrossalternating stages of stationary vanes and rotatable turbine bladeswhich are coupled to a rotor shaft. Kinetic energy is transferred fromthe combustion gas to the turbine blades thus causing the rotor shaft torotate. The rotational energy of the rotor shaft may be converted toelectrical energy via a generator. The combustion gas exits the turbineas exhaust gas and the exhaust gas enters the HRSG. Thermal energy fromthe exhaust gas is transferred to water flowing through one or more heatexchangers of the HRSG, thereby producing superheated steam. Thesuperheated steam is then routed into the steam turbine which may beused to generate additional electricity, thus enhancing overall powerplant efficiency.

Regulatory requirements for low emissions from gas turbine based powerplants have continually grown more stringent over the years.Environmental agencies throughout the world are now requiring even lowerlevels of emissions of oxides of nitrogen (NOx) and other pollutants andcarbon monoxide (CO) from both new and existing gas turbines.

Traditionally, due at least on part to emissions restrictions, the gasturbine load for a combined cycle or cogeneration power plant has beencoupled to or driven by steam production requirements for the powerplant and not necessarily by grid power demand. For example, to meetpower plant steam demand while maintaining acceptable emissions levels,it may be necessary to operate the gas turbine at full-speed full-loadconditions, even when grid demand or power plant demand for electricityis low, thereby reducing overall power plant efficiency.

BRIEF DESCRIPTION OF THE INVENTION

Aspects and advantages of the invention are set forth below in thefollowing description, or may be obvious from the description, or may belearned through practice of the invention.

One embodiment of the present invention is power plant. The power plantincludes a first gas turbine including a compressor, a combustordownstream from the compressor, a turbine disposed downstream from thecombustor and an exhaust duct downstream from an outlet of the turbine.The turbine includes at least one turbine extraction port in fluidcommunication with a hot gas path of the turbine. The exhaust ductreceives exhaust gas from the turbine outlet and the turbine extractionport(s) defines a flow path for a stream of combustion gas to flow outof the hot gas path. The power plant further includes a first gas coolerhaving a primary inlet fluidly coupled to the turbine extraction port, asecondary inlet fluidly coupled to a coolant supply system and an outletthat is in fluid communication with the exhaust duct. The first gascooler provides a cooled combustion gas to the exhaust duct which mixeswith the exhaust gas to provide an exhaust gas mixture to a first heatexchanger downstream from the exhaust duct. The power plant furtherincludes a second gas turbine comprising a compressor, a combustor and aturbine. At least one of the compressor and the turbine is in fluidcommunication with the outlet of the first gas cooler.

Those of ordinary skill in the art will better appreciate the featuresand aspects of such embodiments, and others, upon review of thespecification.

BRIEF DESCRIPTION OF THE DRAWINGS

A full and enabling disclosure of the present invention, including thebest mode thereof to one skilled in the art, is set forth moreparticularly in the remainder of the specification, including referenceto the accompanying figures, in which:

FIG. 1 is a schematic diagram of an exemplary gas turbine basedcogeneration power plant according to one embodiment of the presentinvention;

FIG. 2 is a simplified cross sectioned side view of a portion of anexemplary gas turbine according to at least one embodiment of thepresent invention; and

FIG. 3 is a schematic diagram of the exemplary gas turbine basedcogeneration power plant as shown in FIG. 1, according to one embodimentof the present invention.

DETAILED DESCRIPTION OF THE INVENTION

Reference will now be made in detail to present embodiments of theinvention, one or more examples of which are illustrated in theaccompanying drawings. The detailed description uses numerical andletter designations to refer to features in the drawings. Like orsimilar designations in the drawings and description have been used torefer to like or similar parts of the invention. As used herein, theterms “first”, “second”, and “third” may be used interchangeably todistinguish one component from another and are not intended to signifylocation or importance of the individual components. The terms“upstream” and “downstream” refer to the relative direction with respectto fluid flow in a fluid pathway. For example, “upstream” refers to thedirection from which the fluid flows, and “downstream” refers to thedirection to which the fluid flows.

The terminology used herein is for the purpose of describing particularembodiments only and is not intended to be limiting of the invention. Asused herein, the singular forms “a”, “an” and “the” are intended toinclude the plural forms as well, unless the context clearly indicatesotherwise. It will be further understood that the terms “comprises”and/or “comprising,” when used in this specification, specify thepresence of stated features, integers, steps, operations, elements,and/or components, but do not preclude the presence or addition of oneor more other features, integers, steps, operations, elements,components, and/or groups thereof.

Each example is provided by way of explanation of the invention, notlimitation of the invention. In fact, it will be apparent to thoseskilled in the art that modifications and variations can be made in thepresent invention without departing from the scope or spirit thereof.For instance, features illustrated or described as part of oneembodiment may be used on another embodiment to yield a still furtherembodiment. Thus, it is intended that the present invention covers suchmodifications and variations as come within the scope of the appendedclaims and their equivalents.

In a conventional co-generation power plant, fuel and air are suppliedto a gas turbine. Air passes through an inlet of the gas turbine intothe compressor section upstream of combustors in the gas turbine. Afterthe air is heated by combustors, the heated air and other gases producedin the process (i.e., combustion gas) pass through the turbine section.The full volume of exhaust gas from the gas turbine passes from theturbine section to an exhaust section of the gas turbine, and flows to aheat recovery steam generator (HRSG) that extracts heat from the exhaustgas via one or more heat exchangers to produce steam.

In certain instances, the demand for steam may be lower than the amountof steam that could be generated by the gas turbine exhaust, some of theexhaust gas could be directed away from the heat recovery steamgenerator, such as being transported to an exhaust stack that filtersthe exhaust gas prior to being released into the atmosphere.Alternatively, if steam production is in higher demand than the steamgenerated by the gas turbine exhaust, then an increase in exhaust gasfrom the gas turbine could be produced to generate the steam desired.

The present embodiments provide a system to cool or temper hotcombustion gas extracted directly from a turbine of a gas turbine priorto being mixed with exhaust gas flowing from an outlet of the turbineand for providing a stream of cooled combustion gas to a second orsecondary gas turbine, particularly to a compressor and/or a turbine ofthe second gas turbine. Although the combustion gas is cooled via an gascooler using compressed air extracted from the compressor, the cooledcombustion gas is still significantly hotter than exhaust gas flowingfrom the turbine. As a result, the thermal energy from the cooledcombustion gas raises the temperature of the exhaust gas upstream from aheat exchanger/boiler and/or heat recovery steam generator (HRSG),thereby enhancing steam production from the gas turbine.

The steam may be piped to a steam turbine, used for heat productionand/or for other industrial processes. The system can be used in acogeneration system such that the cogeneration system can produce ahigher quantity of steam without producing a proportional increase ofpower. The embodiment system thus provides an efficient use of the fuelinput into the cogeneration system, and avoids wasteful production ofundesired power by the gas turbine. The potential benefits to the secondgas turbine may include enhanced compressor efficiency, enhanced turbineefficiency and/or enhanced turbine cooling.

The embodiments provided herein provide various technical advantagesover existing cogenerations or combined cycle power plants. For example,the system provided herein may include the ability to modulate steamproduction at a desired level while maintaining thermal and otheroperating efficiencies; the ability to provide a higher temperature gasto produce more steam downstream of the gas turbine; the ability tooperate at a lower power output on the gas turbine and generate moresteam; the ability to minimize wasteful products (i.e., producingunnecessary power in the gas turbine); and the ability to operate acogeneration system at a more cost effective and efficient capacity.

Referring now to the drawings, wherein identical numerals indicate thesame elements throughout the figures, FIG. 1 provides a functional blockdiagram of an exemplary gas turbine power plant 10 with steam productioncapability. The power plant 10 comprises a first gas turbine 100 thatmay incorporate various embodiments of the present invention. The firstgas turbine 100 generally includes, in serial flow order, a compressor102, a combustion section having one or more combustors 104 and aturbine 106. The first gas turbine 100 may also include inlet guidevanes 108 disposed at an inlet or upstream end of the compressor 108. Inoperation, air 110 flows across the inlet guide vanes 108 and into thecompressor 102. The compressor 102 imparts kinetic energy to the air 110to produce compressed air as indicated schematically by arrows 112.

The compressed air 112 is mixed with a fuel such as natural gas from afuel supply system to form a combustible mixture within the combustor(s)104. The combustible mixture is burned to produce combustion gas asindicated schematically by arrows 114 having a high temperature,pressure and velocity. The combustion gas 114 flows through variousturbine stages S1, S2, S3, Sn of the turbine 106 to produce work.

The turbine 106 may have two or more stages, for example, a low pressuresection and a high pressure section. In one embodiment, the turbine 106may be a two-shaft turbine that includes a low pressure section and ahigh pressure section. In particular configurations, the turbine 106 mayhave 4 or more stages. The turbine 106 may be connected to a shaft 116so that rotation of the turbine 106 drives the compressor 102 to producethe compressed air 112. Alternately or in addition, the shaft 116 mayconnect the turbine 106 to a generator (not shown) for producingelectricity. The combustion gas 114 loses thermal and kinetic energy asit flows through the turbine 106 and exits the turbine 106 as exhaustgas 118 via an exhaust duct 120 that is operably coupled to a downstreamend of the turbine 106.

The exhaust duct 120 may be fluidly coupled to a first heat exchanger orboiler 122 via various pipes, ducts, valves and the like. The heatexchanger 122 may be a standalone component or may be a component of aheat recovery steam generator (HRSG). In various embodiments, the heatexchanger 122 is used to extract thermal energy from the exhaust gas 118to produce steam 124. In particular embodiments, the steam 124 may thenbe routed to a steam turbine 126 via various pipes, valves conduits orthe like to produce additional power or electricity. At least a portionof the steam 124 may be piped from the heat exchanger 122 to an onsiteor offsite facility 128 that distributes the steam to users and/orutilizes the steam for secondary operations such as heat production orother industrial operations or processes. In one embodiment, the steam124 may be piped downstream from the steam turbine 126 and furtherutilized for various secondary operations such as heat production orother secondary operations.

Steam flow rate or output from the heat exchanger 122 may be monitoredvia one or more flow monitors. For example, in one embodiment, a flowmonitor 130 may be provided downstream from the heat exchanger 122. Inone embodiment, a flow monitor 132 may be disposed downstream from thesteam turbine 126.

FIG. 2 provides a simplified cross sectional side view of a portion ofan exemplary first gas turbine 100 including a portion of the compressor102, the combustor 104, the turbine 106 and the exhaust duct 120 as mayincorporate various embodiments of the present invention. In oneembodiment, as shown in FIG. 2, the turbine 106 includes an innerturbine casing 134 and an outer turbine casing 136. The inner and outerturbine casings 134, 136 extend circumferentially about an axialcenterline 12 of the first gas turbine 100. The inner turbine casing 134and/or or the outer turbine casing 136 at least partially encasesequential rows of stator vanes and rotor blades that make up thevarious stages S1, S2, S3, Sn of the turbine 106.

The turbine casings 134, 136 are normally sealed with only two openings:a combustion gas inlet at the upstream of the turbine 106, and anexhaust gas or turbine outlet at a downstream end of the turbine 106.The downstream end of the turbine 106 is operably connected to theexhaust duct 120. Conventionally, the entire volume of combustion gas114 passes through a hot gas path 138 defined by the various stages ofthe turbine 106 within the inner and outer turbine casings 134, 136,into the exhaust duct 120 and at least a portion of the exhaust gas 118may be directed out of the exhaust duct 120 to the heat exchanger 122.

During operation, if it is determined that the demand for steamproduction is higher than the demand for power produced by the first gasturbine 100 a portion of the combustion gas 114 may be extracted fromone or more of the turbine stages S1, S2, S3, Sn via one or morecorresponding turbine extraction ports 140 as shown in FIG. 2. Fourturbine extraction ports 140(a-d) are shown for illustration. However,the turbine 106 may include any number of turbine extraction ports 140.For example, the turbine 106 may include one turbine extraction port140, two turbine extraction ports 140, three turbine extraction ports140 or four or more turbine extraction ports 140. Each turbineextraction port 140 is fluidly coupled to and/or in fluid communicationwith one or more of the turbine stages S1, S2, S3, Sn. Each turbineextraction port 140 provides a flow path for a stream of the combustiongas 114 to flow out of the turbine 106 from a point that is downstreamfrom the combustor 104 but upstream from the exhaust duct 120.

As shown in FIG. 2, one or more of the turbine extraction ports 140(a-d)may be in fluid communication with one or more of the turbine stages S1,S2, S3 or Sn via one or more extraction pipes 142. The extractionpipe(s) 142 and the turbine extraction ports 140 provide for fluidcommunication of the combustion gas 114 from the hot gas path 138,through the inner and/or outer turbine casings 134, 136 and out of theturbine 106 to obtain a portion of the combustion gas 114 at highertemperatures than the exhaust gas 118 flowing into the exhaust duct 120from outlet of the turbine 106.

As shown in FIG. 2, the stages in the turbine 106 are successive suchthat the combustion gas 114 flows through the stages from S1 to a laststage Sn. Turbine stage S1 is the first stage and receives hotcombustion gas 114 directly from the combustor 104. Temperature of thecombustion gas 114 decreases with each successive stage. For example,the combustion gas 114 at the S1 turbine stage has a higher temperaturethan at the subsequent turbine stages, S2, S3, Sn, etc . . . The exhaustgas 118 is at a lower temperature than the combustion gas 114 within theturbine 106 and therefore has less thermal energy.

FIG. 3 provides a functional block diagram of the exemplary gas turbinepower plant 10 with steam production capability as shown in FIG. 1,according to one embodiment of the present invention. In one embodiment,as shown in FIGS. 1, 2 and 3, the power plant 10 includes a first gascooler 144. The first gas cooler 144 includes a primary inlet 146fluidly coupled to one or more of the one or more turbine extractionports 140, a secondary inlet 148 fluidly coupled via various pipes,conduits, valves or the like to a coolant supply system 150, and anoutlet 152 in fluid communication with the exhaust duct 120 via variouspipes, conduits, valves or the like. In one embodiment, the first gascooler 144 comprises an ejector. In one embodiment, the first gas cooler144 comprises a static mixer. The static mixer generally includesindividual mixing elements stacked in series within an outer casing orpipe and in fluid communication with the primary and secondary inlets146, 148 and with the outlet 152. Each mixing element may be orientedrelative to an adjacent mixing element to homogenize two or more fluidsflowing through static mixer.

The coolant supply system 150 provides a coolant 154 to the secondaryinlet 148 of the first gas cooler 144. In particular embodiments, asshown in FIGS. 1 and 3, the coolant supply system 150 comprises anambient air supply system 156 for collecting and/or conditioning ambientair upstream from the secondary inlet 148 of the first gas cooler 144.In particular embodiments, as shown in FIGS. 2 and 3 the coolant supplysystem 150 includes the compressor 102 of the first gas turbine 100. Thecompressor 102 may be fluidly coupled to the secondary inlet 148 of thefirst gas cooler 144 via one or more compressor extraction ports 158 andvia various pipes, conduits, valves or the like.

The compressor extraction port(s) 158 provide a flow path for a portionof the compressed air 112 to flow out the compressor 102 at a pointbetween an upstream or inlet to the compressor 102 and an outlet of thecompressor 102 that is defined upstream or immediately upstream from thecombustor 102. Because the compressed air 112 increases in pressure andtemperature from the inlet to the outlet, the compressor extractionport(s) 158 may be axially spaced along the compressor 102 at variouspoints to capture a portion of the compressed air 112 at a desiredtemperature and pressure.

In operation, the extracted combustion gas 114 from the one or moreturbine extraction ports 140 acts as a motive fluid flowing through thefirst gas cooler 144. Ambient air from the ambient air supply 156 or aportion of the compressed air 112 extracted from the compressorextraction port 148 flows into the secondary inlet 148 of the first gascooler 144 and cools the stream of combustion gas 114 upstream from theexhaust duct 120 and may also increase mass flow from the first gascooler 144 into the exhaust duct 120. A cooled combustion gas 160 flowsfrom the outlet 152 of the first gas cooler 144 and is routed into theexhaust duct 120 at a higher temperature than the exhaust gas 118. Thecooled combustion gas 160 mixes with the exhaust gas 118 within theexhaust duct 120 to provide a heated exhaust gas mixture 162 to the heatexchanger 122 disposed downstream from the exhaust duct 120. Thermalenergy from the cooled combustion gas 160 increases the temperature ofthe exhaust gas 118, thereby increasing steam production capability ofthe power plant 10.

In particular embodiments, as shown in FIG. 3, the coolant supply system150 may include a second gas cooler 164 disposed downstream from thecompressor extraction port(s) 158 and upstream from the secondary inlet148 of the first gas cooler 144. The second gas cooler 164 may befluidly coupled to the compressor extraction port(s) 158 and to thesecondary inlet 148 of the first gas cooler 144 via various pipes,conduits, valves or the like. The second gas cooler 164 includes aprimary inlet 166 fluidly coupled to the compressor extraction port(s)158, a secondary inlet 168 in fluid communication with the ambient airsupply system 156 and an outlet 170 in fluid communication with thesecondary inlet 148 of the first gas cooler 144. In this embodiment, thecompressed air 112 from the compressor extraction port(s) 158 acts as amotive fluid through the second gas cooler 164. Air entering thesecondary inlet 168 of the second gas cooler 164 from the ambient airsupply system 156 cools the stream of compressed air 112 upstream fromthe secondary inlet 148 of the first gas cooler 144, thereby enhancingcooling of the combustion gases 114 flowing therethrough. The airflowing into the second gas cooler 164 may also increase air mass flowfrom the compressor extraction port(s) 148 into the first gas cooler144.

In particular embodiments, as shown in FIGS. 2 and 3, the power plant 10further comprises a coolant injection system 172 disposed downstreamfrom the outlet 152 of the first gas cooler 144 and upstream from theexhaust duct 120. The coolant injection system 172 may include spraynozzles, a spray tower, a scrubber or other various components (notshown) configured to inject a coolant 174 from a coolant supply 176 intothe stream of cooled combustion gas 160 flowing from the outlet 152 ofthe first gas cooler 144, thereby further cooling the cooled combustiongas 160 upstream from the exhaust duct 120.

In particular embodiments, as shown in FIGS. 2 and 3, the coolantinjection system 172 may include a mixing chamber 178 fluidly coupled toand positioned downstream from the outlet 152 of the first gas cooler144. The mixing chamber 178 may be fluidly coupled to the exhaust duct120 via various pipes, conduits, valves or the like. The mixing chamber178 may be configured to blend the stream of cooled combustion gas 160from the first gas cooler 144 outlet 152 and the coolant 174 from thecoolant supply 176 upstream of the exhaust duct 120. In this manner, thecoolant 174 may be used to further reduce or control the temperature ofthe cooled combustion gas 160 upstream from the heat exchanger 122and/or the exhaust duct 120. The coolant 174 may be any liquid or gasthat may be mixed with the combustion gas 160 for its intended purpose.In one embodiment, the coolant 174 is water. In one embodiment thecoolant 174 comprises steam.

In various embodiments as shown in FIGS. 1-3, the power plant 10includes a second gas turbine 200 fluidly coupled to and disposeddownstream from the outlet 152 of the first gas cooler 144. The secondgas turbine 200 may be fluidly coupled to the outlet 152 of the firstgas cooler 144 via various pipes, conduits, valves or the like. Thesecond gas turbine 200 comprises in serial flow order, a compressor 202,a combustion system having at least one combustor 204 and a turbine 206.

In particular embodiments, at least one of the compressor 202 and theturbine 206 are in fluid communication with the outlet 152 of the firstgas cooler 144. In one embodiment the compressor 202 is in fluidcommunication with the outlet 152 of the first gas cooler 144. In oneembodiment, the turbine 206 is in fluid communication with the outlet152 of the first gas cooler 144. In one embodiment, both the compressor202 and the turbine 206 are in fluid communication with the outlet 152of the first gas cooler 144. In particular embodiments, a second heatexchanger 208 is fluidly coupled to and disposed downstream from theoutlet 152 of the first gas cooler 144 and is fluidly coupled to anddisposed upstream from the compressor 202 and/or the turbine 206 of thesecond gas turbine 200.

In operation, a portion of the cooled combustion gas 160 may be routedfrom a point downstream from the outlet 152 of the first gas cooler 144but upstream from the exhaust duct 122 to at least one of the compressor202 and/or the turbine 206 of the second gas turbine 200. The cooledcombustion gas 160 may be used to enhance compressor efficiency byadding thermal energy to compressed air 210 being routed to thecombustor 204 and/or may be used for cooling various internal componentsof the turbine 206, and/or for enhancing turbine efficiency by addingthermal energy to the turbine 206. In particular embodiments, the secondheat exchanger 208 may further cool, heat or otherwise condition theflow of the cooled combustion gas 160 upstream from the compressor 202and/or the turbine 206 depending upon the desired intended use of thecooled combustion gases 160 within the second gas turbine 200.

Referring to FIGS. 1 and 3, a controller 300 may be used to determinethe desired steam production capacity and/or to regulate flow of thecooled combustion gas 160 to the second gas turbine 200 by generatingand/or sending appropriate control signals to various control valves 180fluidly coupled to one or more of the turbine extraction ports 140, oneor more control valves 182, 184 of the coolant supply system 150, and/orto one or more control valves 186 (FIG. 2) of the coolant injectionsystem 172 and/or to one or more control valves 188 disposed between theoutlet 152 of the first gas cooler 144 and the second gas turbine 200.The controller 300 may be a microprocessor based processor that includesa non-transitory memory and that has the capability to calculatealgorithms. The controller 300 may incorporate a General ElectricSPEEDTRONIC™ Gas Turbine Control System, such as is described in Rowen,W. I., “SPEEDTRONIC™ Mark V Gas Turbine Control System”, GE-3658D,published by GE Industrial & Power Systems of Schenectady, N.Y. Thecontroller 300 may also incorporate a computer system having aprocessor(s) that executes programs stored in a memory to control theoperation of the gas turbine using sensor inputs and instructions fromhuman operators.

In particular embodiments, the controller 300 is programmed to determinea desired temperature of exhaust gas required to generate the desiredamount of steam flow, to regulate combustion gas flow through valve(s)180, air flow through valve(s) 182, 184, coolant flow through valve 186and cooled combustion gas flow to the second gas turbine via valve 188to achieve the desired temperature of the exhaust gas mixture 162 beingsent to the heat exchanger 122 and to achieve desired flow rate to thesecond gas turbine 200.

In operation, the controller 300 may receive input data signals, such ascooled combustion gas temperature 302 from a temperature monitor 190(FIGS. 1-3) disposed downstream from the outlet 152 of the first gascooler 144, and/or combustion gas temperature 304 from a temperaturemonitor 192 (FIGS. 2-3) disposed at or downstream from the mixingchamber 178, and/or exhaust gas mixture temperature 306 from atemperature monitor 194 (FIGS. 1-3) disposed downstream from the exhaustduct 120 and/or upstream from the heat exchanger 122, and/or coolanttemperature 308 from a temperature monitor 196 (FIG. 3) disposeddownstream from the outlet 170 of the second gas cooler 164, and/orcooled combustion gas temperature 310 from a temperature monitor 198(FIGS. 1-3) disposed at or downstream from the second heat exchanger208.

The controller 300 may also receive steam flow data 312 from flowmonitor 132 and/or steam flow data 314 from flow monitor 130. Inresponse to one or more data signals 302, 304, 306, 308, 310, 312, 314the controller 300 may actuate one or more of valve(s) 180, 182, 184,186, 188 to control combustion gas flow from the turbine stages S1-Sn,compressed air flow rate into the first gas cooler 144 secondary inlet148, coolant flow rate into the mixing chamber 178 and/or cooledcombustion gas flow to the second gas turbine 200, particularly to thecompressor 202 and/or the turbine 206 of the second gas turbine 200 toproduce the desired temperature of the exhaust gas mixture 162 and toproduce the desired temperature of the cooled combustion gas 160 flowingto the second gas turbine 200.

Steam flow output from the steam turbine 126 may be monitored via thecontroller 300 using flow monitor 132. Steam flow output to secondaryoperations may be monitored via the controller 300 using flow monitor130. Controller 300 may actuate one or more of valve(s) 180, 182, 184,186, 188 to control combustion gas flow from the turbine stages S1-Sn,coolant flow rate into the first gas cooler 144 secondary inlet 148,coolant flow rate to the mixing chamber 178 to produce the desiredtemperature of the exhaust gas mixture 162 and/or a desired steam outputfrom the heat exchanger 122 based at least in part on flow output asmeasured by at least one of flow monitors 130, 132.

Data signals received by the controller 300, such as combustion gastemperature, cooled combustion gas temperature, exhaust gas temperature,mixed exhaust gas temperature and steam flow rate, may be analyzed tocompare with a predetermined desired amount of steam flow. Thecontroller 300 may use the received data signals to determine if anincrease in exhaust gas temperature would be desired. Calculationsinclude determining the quantity of steam needed and the amount of powerdesired, and determining the temperature and quantity of combustion gasneeded to produce the desired quantity of steam.

After determining the desired temperature and quantity of combustion gas114 required for the heat exchanger 122 to produce desired steamquantity, the controller 300 may generate and send one or more signals316, 318, 320, 322 (FIGS. 1 and 3) to the receiver of the appropriatevalve(s) 180 to extract combustion gas 114 through the turbine casings134, 136 at the appropriate turbine stage S1, S2, S3, Sn. The controller300 may send a signal 324 to the receiver of either or both valves 182,184 to control the flow rate of the coolant 154 flowing into thesecondary inlet 148 of the first gas cooler 144. The controller 300 mayalso send a signal 326 to valve 186 (FIG. 2) to modulate flow of thecoolant 174 at a desired amount into the mixing chamber 178 and/or intothe stream of cooled combustion gas 160 from the outlet 152 of the firstgas cooler 144 to further cool the cooled combustion gas 160 to adesired temperature. The controller 300 may send a signal 328 (FIGS. 1and 3) to the receiver of valve 188 to control the flow rate of thecooled combustion gas 160 flowing to the second gas turbine 200. Thecontroller 300 and/or the system or systems provided hereinautomatically blend the exhaust gas 118 with the stream of cooledcombustion gas 160 so that the exhaust gas mixture temperature is abovea nominal exhaust gas temperature but below the thermal limits of theheat exchanger 122 or HRSG while providing a stream of cooled combustiongas to the second gas turbine 200, particularly to one or both of thecompressor 202 and/or the turbine 206 of the second gas turbine 200.

Although specific embodiments have been illustrated and describedherein, it should be appreciated that any arrangement, which iscalculated to achieve the same purpose, may be substituted for thespecific embodiments shown and that the invention has other applicationsin other environments. This application is intended to cover anyadaptations or variations of the present invention. The following claimsare in no way intended to limit the scope of the invention to thespecific embodiments described herein.

What is claimed:
 1. A power plant, comprising: a first gas turbineincluding a compressor, a combustor downstream from the compressor, aturbine disposed downstream from the combustor and an exhaust ductdownstream from an outlet of the turbine, the turbine including aturbine extraction port in fluid communication with a hot gas path ofthe turbine, wherein the exhaust duct receives exhaust gas from theturbine outlet and wherein the turbine extraction port defines a flowpath for a stream of combustion gas to flow out of the hot gas path; afirst gas cooler having a primary inlet fluidly coupled to the turbineextraction port, a secondary inlet fluidly coupled to a coolant supplysystem and an outlet in fluid communication with the exhaust duct,wherein the first gas cooler provides a cooled combustion gas to theexhaust duct, wherein the cooled combustion gas mixes with the exhaustgas to provide an exhaust gas mixture to a first heat exchangerdownstream from the exhaust duct; and a second gas turbine comprising acompressor, a combustor and a turbine, wherein at least one of thecompressor and the turbine are in fluid communication with the outlet ofthe first gas cooler.
 2. The power plant as in claim 1, furthercomprising a second heat exchanger fluidly coupled between the outlet ofthe first gas cooler and the second gas turbine.
 3. The power plant asin claim 2, wherein the second heat exchanger extracts thermal energyfrom the cooled combustion gas upstream from the second gas turbine. 4.The power plant as in claim 1, wherein the first heat exchanger extractsthermal energy from the exhaust gas mixture to produce steam.
 5. Thepower plant as in claim 1, further comprising a steam turbine disposeddownstream from the first heat exchanger.
 6. The power plant as in claim1, wherein the first gas cooler comprises an ejector.
 7. The power plantas in claim 1, wherein the first gas cooler comprises an inline staticmixer.
 8. The power plant as in claim 1, wherein the coolant supplysystem comprises an ambient air intake system fluidly coupled to thesecondary inlet of the first gas cooler.
 9. The power plant as in claim1, wherein the coolant supply system comprises the compressor of thefirst gas turbine, wherein the compressor is fluidly coupled to thesecondary inlet of the first gas cooler via a compressor extractionport.
 10. The power plant as in claim 1, wherein the coolant supplysystem comprises a second gas cooler having a primary inlet fluidlycoupled to the compressor of the first gas turbine, a secondary inletfluidly coupled to an ambient air intake system and an outlet in fluidcommunication with the secondary inlet of the first gas cooler.
 11. Thepower plant as in claim 10, wherein the second gas cooler comprises anejector.
 12. The power plant as in claim 10, wherein the second gascooler comprises an inline static mixer.
 13. The power plant as in claim1, wherein the turbine of the first gas turbine comprises an innercasing, an outer casing and an extraction pipe in fluid communicationwith at least one turbine stage of the turbine, wherein the extractionpipe is in fluid communication with the turbine extraction port.
 14. Thepower plant as in claim 1, further comprising a coolant injection systemdisposed downstream from the first gas cooler outlet and upstream fromthe exhaust duct, wherein the coolant injection system injects a coolantinto the stream of cooled combustion gas flowing from the first gascooler outlet.
 15. The power plant as in claim 14, wherein the coolantis water.
 16. The power plant as in claim 14, wherein the coolant issteam.
 17. The power plant as in claim 1, further comprising acontroller electronically coupled to a first control valve fluidlyconnected between the turbine extraction port and the first gas coolerprimary inlet and a second control valve disposed upstream from thesecondary inlet of the first gas cooler.
 18. The power plant as in claim17, further comprising a temperature monitor electronically coupled tothe controller and in thermal communication with the turbine extractionport upstream from the exhaust duct, wherein the controller actuates atleast one of the first control valve to increase or decrease the streamof combustion gas from the turbine and the second control valve toincrease or decrease mass flow through the secondary inlet of the firstgas cooler in response to a data signal provided by the temperaturemonitor to the controller.
 19. The power plant as in claim 17, furthercomprising a steam flow monitor disposed downstream from the first heatexchanger and electronically coupled to the controller, wherein thecontroller actuates at least one of the first control valve and thesecond control valve in response to a flow output signal provided to thecontroller by the steam flow monitor.